Method and apparatus for formation damage removal

ABSTRACT

A method of removing formation damage through the controlled injection of fluids into the formation, followed by a controlled sudden release of pressure in the formation, an under-balanced surge, which causes fluid and damaging materials to flow back into the well bore. This method is most effective when repeated more than once.

FIELD OF INVENTION

[0001] This invention relates to methods and apparatus for treatingunderground formations to remove formation damage.

BACKGROUND OF THE INVENTION

[0002] The production of hydrocarbons from underground reservoirs isoften hampered by a damaged zone in the reservoir rock around the wellbore.

[0003] These damage mechanisms include:

[0004] 1. Drilling damage caused by the high velocity of drilling fluidspassing through the jets in the drilling bit which can force liquid andparticulate matter beyond the well bore out into the reservoir porespaces.

[0005] 2. Plugging of the pore spaces in the reservoir regionimmediately around the drilled well bore can be caused by formation rockmaterial from the drilling process. These drill cuttings and fines canbe forced into the pore spaces of the surrounding rock by severalmechanisms; the rotation of the drill string and the weight of thatdrill string can put very high forces on particulate matter trappedbetween the drill string and the face of the well bore, compacting itinto the pore spaces of the formation; or the pressure of the fluid inthe well bore, which-is normally higher than the pressure in thesurrounding reservoir, can force drilling fines beyond the compactionzone and into the surrounding pores

[0006] 3. Plugging of the pore spaces around the well bore can also bethe result of particulate matter added to the drilling fluids to createa filter cake around the well bore which is intended to minimize theleak off of liquids into the surrounding reservoir. The mechanisms thatforce this particulate matter into the pore spaces are identical tothose that cause damage from drilling fines, notably pressure, force andvelocity.

[0007] 4. Pore space reduction can occur as a result of alteration tothe reservoir materials in the region surrounding the well bore. Themost well known damage of this type is caused by clays in the reservoirwhich absorb fluids, most often water, and swell in physical size. Thisswelling reduces the size of the pore spaces and often reduces thepermeability to the flow of reservoir hydrocarbons. This type of damageis often very difficult to remove or alter, and usually requires ahydraulic fracture with compatible fluids to bypass the damaged zone.

[0008] 5. Fluid blockage in the region around the well bore results whenthe naturally occurring fluids in the reservoir are replaced by fluidsinjected during drilling or well service operations. Drilling fluids,fresh water, salt water, acids, acid reaction products, and otherchemicals that are used in well operations can result in fluid blockage.These fluids can alter the surface tension between the rock and thefluid, which can have a dramatic impact on fluid mobility andproduction. Emulsions and colloidal suspensions are two specific typesof fluid blockage.

[0009] The development of horizontal drilling technology has providedadditional challenges with respect to formation damage. In verticalwells, it normally only takes a matter of hours to drill through ahydrocarbon bearing formation and establish a stable filter cake on theface of the well bore to prevent further damage due to migration ofsolids and fluids. In horizontal wells however, drilling of theproducing formation can take several days or longer which means that theformation is exposed to drill cuttings, drilling fluids and pressure fora much longer period of time than a conventional vertical well. Thefilter cake which helps to prevent fluid loss and invasion ofparticulate matter into the formation is much more susceptible to beingremoved by the weight, rotation and axial movement of the drill pipetool joints. This can lead to a damaged region around the well borewhich is much larger in aerial extent and is more severely damaged thanis the case for a vertical well bore.

[0010] In practice, damage removal in producing hydrocarbon reservoirshas been achieved through the use of primarily two techniques, acidizingand hydraulic fracturing. In carbonate reservoirs, acid injection todissolve some of the rock material has proven to be effective in manysituations. It is generally only when the damage is so severe as toprevent any injection of acid into the formation, that acid does notreduce the damge and improve production.

[0011] The use of acid to remove damage in reservoirs which have anactive water drive can result in very serious production problems if theacid opens up channels into the water bearing portion of the reservoir.This situation can lead to very high water production levels which mayrender the well uneconomic to produce.

[0012] In sandstone reservoirs, acid is much less effective in reducingdamage, particularly if the damaged region around the well bore isrelatively deep or if the damage is severe. It is common practice insandstone reservoirs to use hydraulic fracturing to create a fracture inthe formation which extends beyond the region of damage and provides aflow channel from the undamaged formation to the well bore.

[0013] Virtually all well stimulation methods are based upon providing apressure surge in the well bore or in the formation. One of the firstmethods utilized for oil well stimulation involved dropping containersof nitro-glycerin down wells, which caused a high pressure surge whenthe nitro-glycerin exploded. Even acidizing and fracturing operations onwells can be classified as surge techniques since they employ the use ofpositive pressure across the well bore to formation interface. Numerousother surge techniques have been developed over the years including,underbalanced perforating systems, overbalanced explosive “Stress-Frac”type systems, drop bar surge completion techniques, and more recently,extreme overbalanced perforating systems.

[0014] Some of these techniques use a long pressure cycle and some ofthem use an extremely short pressure cycle of less than a second. Theygenerally use either a positive or a negative pressure differentialacross the well bore to formation interface, but not both. The pressuresurge initiation can be either at surface or down hole in closeproximity to the formation face. These techniques can involve theinjection of solids (fracturing), liquids (acidizing) or gases(perforating) across the well bore formation interface.

[0015] It is common in the industry during stimulation operations thatinvolve pumping fluid into the formation, to use a tubing string toconvey the treating fluids to the well bore adjacent to the formation.This provides more control over displacement of the fluids, allowshigher treating pressures and allows packers and other down hole flowcontrol devices to be utilized. The tubing can be either jointed tubingor continuous coiled tubing.

[0016] It is also common in the industry to utilize sealing elementssuch as packers to isolate a segment of the well bore which can be“selectively” stimulated, without stimulating the remainder of the wellbore. A single sealing element can be used to divide the well bore intotwo regions, the first region being below the sealing element and thesecond region being above the sealing element. Two sealing elements canbe utilized to isolate a smaller region of the well bore from theregions below the lower packer and above the upper packer. Down holedevices such as fluid control valves, circulating valves and packerinflation valves which function either by mechanical or hydraulic meansare well known in the industry.

[0017] In horizontal wells with long open hole sections of up to severalthousands of feet, it can be appreciated that without selectivestimulation tools, all treating fluids will follow the path of leastresistance or least formation damage. As a result, it is possible forall of the stimulation fluids to enter the formation at the same point,and that no stimulation of the remaining formation will occur. Bothgross stimulation techniques and selective stimulation techniques fortreatment of horizontal wells are commonly practised.

[0018] U.S. Pat. No. 4,898,236 and Canadian patent No. 1,249,772 to Saskand discloses a drill stem testing system which includes inflatablepackers to isolate well bore regions for evaluation. Sask also discloseselectrically operable valves for allowing fluids to flow between thevarious regions within and surrounding the down hole drill stem testingapparatus. However, it should be noted that Sask discloses the use oftwo position electrically operable valves which are biassed to oneposition, which necessitates the use of multiple electrically operablevalves to accomplish the tasks required for drill stem testingoperations.

[0019] Sask also discloses the use of an electrically operable pump forwithdrawing fluids from the well bore and providing those fluids underpressure to expand inflatable type packers.

[0020] In a long horizontal well bore there is often a significantamount of particulate matter which in a vertical well would fall to thebottom of the well bore. Any packer inflation means utilizing well borefluids for expanding packers in a horizontal well has the inherent riskof plugging either the pump or the packers with well bore particulatematerials, particularly where the packers must be expanded a number oftimes to selectively evaluate or stimulate discreet segments of the wellbore.

SUMMARY OF THE INVENTION

[0021] The present invention differs from what is taught in the priorart, in that in one aspect of the invention it teaches a method ofremoving formation damage through the controlled injection of fluidsinto the formation, followed by a controlled sudden release of pressurein the formation, an under-balanced surge, which causes fluid anddamaging materials to flow back into the well bore. This method is mosteffective when repeated more than once. Its effectiveness in the removalof formation damage and subsequent improvement in fluid production isdue to one or more of the following factors.

[0022] 1. A method of removal of the solid, liquid or multi-phasematerials causing the damage in the formation is preferable to and moreeffective than a method of simply dispersing this damaging materialfurther into the formation. Creating a positive pressure surge into theformation tends to force materials deeper into the formation, whereascreating a negative pressure surge from the formation to the well boretends to remove materials into the well bore. It is therefore better toutilize a negative pressure differential from the formation to the wellbore to obtain the best stimulation results.

[0023] 2. The ability to control the surge at the formation face, ratherthan at the surface, is preferred since it allows for more instantaneousrelease of the pressure, resulting in higher velocities in the near wellbore region where the formation damage exists.

[0024] 3. The use of nitrogen or other gas as a stimulation fluidprovides deeper penetration into the formation as a result of theability of gas to penetrate smaller pore space and openings within theformation.

[0025] 4. The expansion and low density of gases can be used to createsignificantly highe fluid velocities in the area surrounding the wellbore, when the pressure on the formation is released during the surgecycle, than can be achieved with liquid treatments. This gas expansionalso means that the higher velocity will be maintained for a longer timeduration than if liquid is injected. The lower density of gas, theability to vent gas flowing into the well bore at surface, and the lackof a hydrostatic pressure buildup, means that a higher pressuredifferential can be maintained between the well bore and the formation.

[0026] 5. If one surge can improve productivity through damage removal,then repeated surges should provide even more thorough damage removal.It is highly unlikely that all formation damage will be removed througha singular surge.

[0027] 6. The use of gas can be effective in fluid blockage or whereemulsions have formed because the gas molecules are smaller and candiffuse into the liquids. When the pressure is released, the gasmolecules will expand and will force some of the liquid to move from theformation into the well bore along with the gas. Repeated surges canresult in significant liquid blockage removal.

[0028] For the reasons stated above, a preferred embodiment of thepresent invention utilizes gas as a stimulation fluid. However, liquidsor multiple phase fluids can also be utilized with the method of thisinvention.

[0029] In a further aspect of the invention, in order to providemultiple surge capability using gas, and to be able to inject the gasand then very quickly surge it back into the well bore, two fluidchannels are provided. One fluid channel is used for injection of fluidsinto the reservoir and a second is used for removal of fluids and solidsfrom the formation. Prior art stimulation practices were prevented orseverely limited from providing this capability since injection andremoval had to take place in the same flow path.

[0030] In a further aspect of the invention, a down hole valve or seriesof valves is provided to control the flow of fluid from the injectionfluid channel into the formation and from the formation back into thereturn fluid channel.

[0031] Although it is possible to inject fluids using prior arttechnology and it is possible to surge a well once using under-balancedperforating or rupture disk techniques, the ability to surge a welleffectively more than once with a single flow channel can not beaccomplished for several reasons.

[0032] The first limitation is that in order to flow the well back, thepressure must be released from the tubular string. If liquid has beeninjected, the pressure which has been applied at surface can be releasedvery quickly since liquid is relatively incompressible, and the pressuredown hole will decrease by the same amount that the surface pressuredecreases. However, the pressure at the lower end of the tubing, whichis still being applied against the formation, will be equal to thehydrostatic pressure of the liquid column in the tubular string. In mostinstances, this hydrostatic pressure will be greater than the reservoirpressure and the resulting surge will be minimal and relativelyineffective.

[0033] If gas has been injected into the formation, then as the pressureis released at surface, the expansion of the gas in the tubing will setup a pressure gradient along the tubing as virtually all of the gasinjected into the tubing will flow back out of the tubing. Therefore itwill take a long time for the pressure at the down hole end of thetubing to decline and this decline will be very gradual. The result willbe a low fluid velocity in the formation and the lack of any effective“surge” to force damaging materials from the formation into the wellbore.

[0034] If a valve is placed down hole and closed after the injection hasstopped, the gas pressure in the formation can be better maintainedwhile the tubing pressure is bled off and will provide the ability tosurge the formation when the valve is opened. However, a significantamount of the injection pressure may be dissipated into the formationduring the lengthy time period required to bleed down the tubingpressure.

[0035] The release of pressure from the tubing and re-pressurization foranother injection cycle requires significant time, particularly if gasis utilized. This is operationally more complex than the method of thepresent invention and increases the costs of the treatment, especiallyas a result of substantially higher gas volumes required.

[0036] It can be appreciated from the preceding discussion that the useof a down hole fluid control valve to control the injection of fluidsinto the formation and to control the release of fluids from theformation would have a beneficial impact on the development of a surgestimulation method.

[0037] For the preceding reasons, it should also be appreciated that asurge technique will be more effective if a second fluid channel existsin which the pressure can be released back to surface. There are severaloptions that provide the ability to achieve a dual flow configuration.

[0038] 1. Two strings of jointed tubing, run side by side, can beutilized. The fluid control valve(s) allow injection down one string andflow back up the other string.

[0039] 2. Concentric string tubing comprised of coiled tubing inside ofjointed can be used The fluid control valve(s) allow injection down theouter string and flow back up the inner string.

[0040] 3. Concentric string tubing with coiled tubing inside of coiledtubing can be used. The fluid control valve(s) allow injection down theouter string and flow back up the inner string.

[0041] 4. A single string of tubing can be utilized in conjunction withthe well bore annulus. This requires that the well bore annulus beessentially empty of liquid, or with a low fluid level. The stimulationapparatus disclosed in the present invention provides thisconfiguration.

[0042] In a further aspect of the invention, there is disclosed a noveldownhole valve system, in which a series of ports are selectivelycoupled together to allow flow of fluids through the valve system. Theuse of clean fluids supplied down a tubing string also provides adistinctive advantage in reducing the risk of plugging the inflationsystem.

[0043] In an aspect of the valve system invention, there is proposed theuse of a micro-controller and an electrically driven valve. Thesefeatures have distinct advantages over mechanically or hydraulicallycontrolled valves. For a preferred embodiment of the method beingdisclosed in this patent, four mechanical or hydraulic valves would berequired for complete operation. In order to control these valvesindividually would require very complex mechanical or hydraulicoperations. Mechanically, only tension or compression can be utilizedsince it is not possible to rotate coiled tubing. In a well with a longhorizontal section, the ability to precisely apply tension orcompression for manipulating a valve can be difficult if not impossibledue to severe friction between the coiled tubing and the well bore.

[0044] The use of hydraulic pressure for sequencing four distinct valveswould require a complex array of pressure settings and could severelylimit the flexibility of the treatment procedure as compared to thesingular multiple position fluid control valve disclosed in this patent.In one aspect of the method of the invention, the surge stimulationmethod uses a short injection cycle followed by the immediate release ofpressure. The use of a multiple position fluid control valve has a levelof simplicity in design which will effect reliability of the stimulationtool in a very positive manner.

[0045] In another aspect of the invention, a wireline conductor betweenthe surface computer and the down hole apparatus allows both power andcontrol commands to be sent from surface to the down hole apparatus.Data measurements in the down hole apparatus, such as pressure andtemperature, can be sent back to the surface computer. The importance ofreal time data in drill stem testing operations is discussed in the Saskpatent.

[0046] In a further aspect of the invention, there is provided a methodfor stimulating the production of fluids from subsurface regionssurrounding a well bore. This method relates to the technique ofinjecting and removing stimulation fluids from the formation in acontrolled surging method.

[0047] In one aspect of the invention, fluids are injected at pressureshigher than the formation pressure in order to create a zone around thewell bore of higher pressure than what is in the formation. Thisinjection period to create a positive surge, will be for a relativelyshort period of time, normally in the order of minutes. The injectionperiod may or may not be followed by a brief transition time to allowthe injected fluid to mix with and associate with the formation fluidsor formation materials. The pressure in the formation is then releasedto a conduit in the well bore which creates a negative surge and allowsthe pressure to fall back to or less than the native formation pressure.This surge process can be repeated any number of cycles to facilitatemore complete removal of the formation damage around the well bore.

[0048] In a further aspect of the invention, there is provided a methodfor evaluating the permeability and formation damage in the porous rockaround a well bore. This method relates to the use of a single stringcoiled tubing and a down hole assembly which includes a microcontroller,an electrically operable fluid control valve and electrically operablepressure sensing devices which allow for real time pressure transientanalysis techniques before, during and after formation stimulationtreatments.

[0049] In another aspect of the invention, a down hole evaluation andstimulation system is provided which allows these methods to beperformed in a well. The down hole tool is lowered into the well at theend of a string of segmented tubing or continuous coiled tubing. In oneaspect of the invention, the tool comprises of a number of elongatedhousings which direct fluid between the various regions around the downhole tool. An inventive aspect of the tool is a valve arrangement whichdirects flow between the various separate regions This valve arrangementallows for the injection of high pressure fluids down a conduit fromsurface into the subsurface reservoir. The arrangement also allows theflow of injected fluids to be stopped at the down hole tool withoutbleeding back the pressure in the conduit. The valve arrangement iscapable of releasing the pressure in the subsurface formation back to asecond conduit which is also connected to the surface.

[0050] These and other aspects of the invention are described in thedetailed description and claimed in the claims that follow the detaileddescription.

BRIEF DESCRIPTION OF THE DRAWINGS

[0051] There will now be described preferred embodiments of theinvention, with reference to the drawings by way of illustration only,in which like reference characters denote like elements and in which:

[0052]FIG. 1 is a section showing a typical well bore region during thedrilling process, and shows three major types of formation damageinduced by the drilling process.

[0053]FIG. 2 is partly in section (below ground), and partly a schematicside view (above grund), shows one embodiment of the present inventionand the delivery system for placing the down hole stimulation tool intothe horizontal well bore. The tool is delivered into the well at the endof a string of coiled tubing, which is a typical coiled tubing stringwith conducting wireline inside of the tubing.

[0054]FIG. 3 is a section showing an exemplary down hole stimulationtool according to the invention.

[0055]FIGS. 4a, 4 b and 4 c are respectively cross sectional views of afluid control valve according to the invention, including the electricalboard and valve system (FIG. 4a), pressure sensors in a sectionperpendicular to the section of FIG. 4a (FIG. 4b) and the valve systemitself (FIG. 4c).

[0056]FIGS. 5a-5 e are schematics showing a fluid control valveaccording to the invention in five differing positions and show thefluid passage ways which connect to the valve in each of these variouspositions.

[0057]FIG. 5f shows a schematic representation of the flow paths throughthe fluid control valve.

[0058]FIG. 6 is a schematic showing a software architecture overview forthe control of a downhole stimulation tool according to the invention;

[0059]FIG. 7 is a schematic showing the electronics for a downhole toolaccording to the invention.

[0060]FIGS. 8a-d and FIGS. 9a-d are representations showing treatment ofa formation according to the method steps.

DESCRIPTION OF PREFERRED EMBODIMENTS OF THE INVENTION

[0061] This description is of preferred embodiments and is intendedmerely to be illustrative and not limiting of the claims. The wordcomprising as used in the description and claims means “including” andnot “consisting”. Where an element is referred to in the claims as “a”or “an” element, then that does not exclude the possibility that morethan one of those elements exists. Where an element is referred to asbeing “necessary” or “required” that is a reference to that particularaspect of the invention and not necessarily to all aspects of theinvention.

[0062] Formation damage, or blockage of the pore spaces in the regionaround a well bore, can result in reduced production of fluids from thereservoir. FIG. 1 shows the three primary types of formation damagecreated during the well drilling process; a compaction zone, a zone ofsolids invasion, and a larger zone of fluid invasion.

[0063] During the drilling process, drilling fluid 4 is pumped underpressure down the drill string which can include one or more drillcollars 2 and through the drilling assembly including a drill bit 3. Thedrill bit has teeth which grind the rock materials of the formation intopieces.

[0064] The size of the rock cuttings can vary from as large as an inchacross, to very small crushed particles. With forces of severalthousands of pounds being applied to the drill bit, as well as very hightorque at the drill bit, the drill cuttings can become very compacted atthe face of the well bore and forced into the pore spaces of theformation 7.

[0065] The velocity and pressure of the drilling fluids passing throughthe nozzles of the drill bit can also force the small formation solids,as well as particulate matter in the drilling fluid itself, out furtherinto the formation 8 from the well bore. The major purpose of thedrilling fluids is to carry the drill cuttings up the well bore annulararea 5 to surface. When the pressure of the drilling fluid in the wellbore is greater than the formation pressure, liquid from the drillingfluid will tend to leak off into a fluid invaded zone 9 surrounding thewell bore. If the drilling fluid has high fluid loss characteristics,this invaded zone can be very large, extending hundreds of feet indiameter from the well bore.

[0066] Formation damage can be evaluated, reduced and removed from thearea around a well bore through the methods and apparatus of the presentinvention. The stimulation description details how the method andapparatus are employed to improve the well performance, and theevaluation description details how the apparatus can improve theunderstanding of well performance before, during and after a stimulationtreatment.

[0067] Stimulation Treatment Method and Apparatus

[0068] The following description of the present invention will firstdisclose one embodiment of an apparatus for removing formation damageand increasing the rate of fluid flow from the formation into the wellbore. An inventive method for removing the formation damage from thearea around the well bore using this or other similar apparatus willthen be disclosed.

[0069]FIG. 2 is one embodiment of the present invention andschematically shows a formation stimulation tool 19 positioned within ahydrocarbon bearing subsurface reservoir 6, which has a damaged region10 around the well bore 1. The well bore has been drilled verticallyfrom a surface well location to a depth of several thousand feet andthen drilled directionally until a horizontal well profile has beenattained. The well has then been drilled horizontally for a distance ofseveral thousand feet. The well bore may be cased to the start of thehorizontal section, or in some instances, it may be cased in itsentirety. The stimulation tool has been attached to the end of aelongated string of coiled tubing 11 and lowered into the well bore.

[0070] The equipment utilized at the well surface is well known in theindustry. The coiled tubing is spooled from a reel 13 which is mountedon a truck 12. The tubing passes over a goose-neck 15, and through atubing injector 16, a blowout preventor stack 17 and the wellhead 18. Alubricator stack can be added to this arrangement for pressuredeployment of the tools and tubing in a live well environment. Thecontrols for the coiled tubing unit are contained in the recorder cab14, along with recording and control equipment for the formationstimulation tool.

[0071] The methods of deploying or inserting the stimulation tool intothe well bore at surface are known in the industry. If the well bore isfilled with liquid and does not flow when open at surface, it is in anover-balance condition, and normal deployment will be used. Thisinvolves lowering the tool into the well bore until just the top endremains above the blow out preventors and is held in that position withtool slips. The coiled tubing is then lowered until it engages and islocked into the connector at the top of the tool. The slips are removedfrom around the tool and it is lowered and the coiled tubing injector islowered and connected to the top of the blow out preventor stack. Thecoiled tubing and tool can then be lowered into the well to the desireddepth.

[0072] In the event that the well bore is under-balanced or void ofliquid, the tool must be deployed using industry known pressuredeployment techniques to prevent potentially dangerous formation fluidsfrom escaping from the well bore while the stimulation tool and tubingare being inserted into the well bore.

[0073]FIG. 3 shows the major components of the stimulation tool. Thetool is attached to the end of the coiled tubing 11 and to theconducting wireline 21 which is inside of the coiled tubing by aconnector section 20. The electronics section 27 provides componentsthat allow the pressure and temperature in the down hole tool andsurrounding well bore regions to be recorded. This recorded data istransmitted via the wireline 21 to the operators computer in the coiledtubing truck recorder cab, where it can be viewed, graphed and analysed.The electronics section also provides components for operating themulti-position fluid control valve 28. The operations computer is shownin FIG. 7, and it may be a general purpose computer programmed inaccordance with the description of the invention disclosed here. Theprogramming of the computer is a matter well within the skill of acomputer engineer in the oil industry based on the present disclosure.

[0074] The tool is shown in a dual packer embodiment, which allows adiscreet segment of the well bore to be evaluated or stimulated,independent from the remainder of the well bore. The tool can also beconfigured with a single packer, which allows all of the well bore belowthe packer to be treated. In addition, it is contemplated that more thantwo packers could be placed in the tool string allowing more than onediscreet segment to be treated simultaneously or independently. Thepackers 23 and 26 are inflatable type packers manufactured by any one ofa number of packer manufacturers. These inflatable packers are expandedby applying pressure internally to expand the rubber element until itcontacts the well bore. Other types of packers could also be used inspecific well circumstances, such as when the well has been cased, or aliner has been installed in the well.

[0075] The size of the well bore segment to be treated is variable,depending upon the length of spacer 24 placed between the packers. Thespacer pipe contains an internal bypass pipe 25 which allows fluidcommunication between the sections of the well bore above and below thepackers, through ports 30 and 33 in the tool, and prevents pressuredifferential and any resulting axial forces from being applied to thepackers.

[0076] A release tool 22 is included in the stimulation tool in order toallow the tool to be separated in the event that the packers 23, 26become lodged in the well bore by solids or other debris. Releasing thetool above the packers 23, 26 allows the tubing 11 and upper portion ofthe tool to be retrieved from the well, after which the packers 23, 26can be retrieved with circulating and fishing tools.

[0077] One inventive feature of the present disclosure is the fluidcontrol valve 28. The fluid control valve in combination with a dualflow path configuration in the well bore have been found to provide mosteffective surge stimulation. FIGS. 4a, 4 b and 4 c show severalsectional views of the fluid control valve. The valve is containedwithin a valve bore 44 in the valve housing 47, which has a number offluid passages within it, two of which are shown as 49 and 50.

[0078] The valve 28 is operated from surface by computer control in thesystem software. The computer operator selects the desired position forthe valve 28, and the computer issues the necessary software commands tocarry out the necessary action. The command is sent through acommunications module such as a modem (not shown, but is conventional)down the wireline to a second receiving modem 68 in the down holeelectronics circuit boards 76 which conveys the command to themicro-controller 67. The modem 68 is a commercially available device.The micro-controller 67, also readily commercially available, butprogrammed in accordance with the patent description, determines whichdirection the actuator motor 34 must rotate, and turns on a switchingdevice 71 which supplies power in the appropriate polarity from thepower supply 70 to the actuator motor 34. The motor 34 is coupled to arotating shaft 36 which is threaded externally and which rotates insideof a threaded non-rotating linear shaft 37. The non-rotating shaft 37 isheld in place by the actuator housing 38, which allows linear motion butprevents the shaft 37 from rotating.

[0079] A contact 41 is mounted on the linear shaft 37, and providescontact with a series of limit switches 40 which are mounted along theactuator housing 47. These switches 40 are electronically connected tothe micro-controller 67 and provide feedback to the micro-controller 67regarding the position of the contact. The micro-controller 67 willrecognize when the contact reaches the desired switch 40, indicatingthat the valve 28 is in the correct position, and will switch off thepower to the motor 34.

[0080] The linear shaft 37 is coupled to a valve sleeve 42 which issealed to the housing 47 by seals 43 and 48 and an area of reduceddiameter 51 which allows fluid to flow between any two adjacent ports inthe valve bore which are connected to fluid channels such as 49 and 50.There are five ports, in the valve bore which provide fluid channels tofour regions corresponding to the packers, tubing, formation andannulus, within the down hole tool and well bore region. As can be seenfrom the number of limit switches 40 in FIG. 4, there are seven distinctpositions at which the actuator 34 and valve spool 42 can be stopped.Four of these positions allow flow between any two adjacent ports, andthe remaining three positions are closed positions which do not allowflow between any ports.

[0081] The valve spool 42 has a hole through the centre of it 55, whichequalizes the pressure at each end of the spool and prevents the spoolfrom becoming pressure locked as it is extended or contracted.

[0082] The down hole tool contains four electrical pressure transducersor pressure sensors 72-75 which measure the pressure in four separateregions of the tool and well bore. The sensors 72-75 are distributedaround the tool at the same approximate level as the actuator 34. Asshown in FIGS. 4a and 4 b, the tool housing 80 is shown incross-section, with the cross-section of FIG. 4a perpendicular to thecross-section 4 b. Sensor 72 senses the outside pressure in the wellbore through port 81 in the housing 80. Sensor 73 senses tubing pressurein channel 50 leading to the tubing 11. Sensor 74 senses inflationpressure in the packers 23, 26 through channels 49 and 54. Sensor 75senses formation pressure through channel 52. These sensors 72, 73, 74and 75 provide an electrical output which is connected to a signalprocessor 69 and the microprocessor 67. The pressure sensors 72-75 areconventional sensors that may or may not have temperature sensorsintegrated into the pressure sensor body. The microprocessor 67 sendsthe pressure information, temperature information and contact switchposition information through the receiving modem 68 back to the computerat the surface of the well.

[0083] The control of fluid through the stimulation tool from thevarious regions of the well bore and tool around the valve can be morefully understood with FIGS. 5a-5 e. FIG. 5a shows the valve 28 in theinflation position with fluid flowing from the tubing 11, through flowchannel 50 into the valve bore 44 and then out through fluid channel 49to the packers 23, 26. FIG. 5b shows the valve in the injection positionwith fluid flowing from the tubing 11, through flow channel 50 into thevalve bore 44 and then out through fluid channel 52 to the well borearea between the packers and into the formation. FIG. 5c shows the valve28 in the surge position with fluid flowing from the formation into thewell bore and through flow channel 52 into the valve bore 44 and thenout through fluid channel 53 into the well bore above the packer 23.FIG. 5d shows the valve 28 in the deflation position with fluid flowingfrom the packers 23, 26, through flow channel 49 into the valve bore 44and then out through fluid channel 53 into the well bore above thepackers 26. FIG. 5e shows the valve in the closed position with theseals covering all ports except the port to flow channel 50.

[0084] The computer control and data acquisition system can be morefully understood with FIG. 6 and FIG. 7. The software architecture asshown in FIG. 6 utilizes a standard commercially available desktop styleor notebook style computer 85 which is linked to a tool interface 86 andthen to the down hole tool electronics section 27 through the wirelinecable 21. The computer 85 runs commercially available software which hasbeen programmed to include an operator interface task 87 which is linkedto a date management task 88, a database storage medium 89, a deviceinterface task 90, a calculation task 91 and a report generation task92. An external computer 101 with software and database management tasksoftware, located remotely from the well operations, can be connected toallow personnel not at the well site to observe the data.

[0085]FIG. 7 shows the software functions in the down hole tool whichinclude three communications interfaces from the standard communicationbus 93 of the micro-controller to; i) an interface 100 to a receivingmodem 68 which is linked through the wireline cable 21 to the surfacecomputer 85; ii) a communications interface 95 to the valve controllerlogic 94 which controls the switching device (output driver) 71 andthereby the actuator motor (valve) 34 and to the limit switches(position detection) 40; and iii) a communication interface 96 whichtakes raw signals from the pressure transducer 72 through the signalamplifier 69 and the analog to digital convertor 97 and uses calibrationcoefficients 98 to obtain engineering values 99.

[0086] The preferred procedures for obtaining optimum results with therepeated surge stimulation method are provided by the followingdescription and by FIGS. 8a-d and FIGS. 9a-d. This description willdisclose an inventive method for the removal of flow restricting(damaging) materials from the well bore surface and from the regionaround the well bore. It assumes that a stimulation tool such aspreviously disclosed has been lowered into a well with an oil bearingformation that has significant formation damage, very little inflow ofoil into the well bore, and a very low fluid level in the well bore. Italso assumes that the tool has been lowered on the end of a single coiltubing string and that the tool was pressure deployed into the well borein order to maintain a low fluid level in the well bore.

[0087] Once the stimulation tool has been lowered to the desired depthin the well and all of the surface pumping and flow control equipmenthave been assembled and tested, stimulation operations can commence.Nitrogen is pumped into the coiled tubing at surface until the pressurein the tubing at the stimulation tool is approximately 800 psi above thepressure in the well bore at the tool. At that time, the stimulationengineer, who will be monitoring these pressures, will put the fluidcontrol valve in the inflation position and allow the nitrogen toinflate the packers. After the packers have been fully inflated, thefluid control valve is closed, trapping pressure in the packers.

[0088]FIG. 8a shows a section of an oil bearing reservoir with formationparticles 66 surrounded by reservoir fluids 65 which will typicallyinclude oil as well as some amounts of water and gases. FIG. 8b showsthe formation with a well bore 1 drilled through it, along withformation damage from the drilling process, including a zone of solidsinvasion 56 and a zone of liquid invasion 57, which have displaced theoil 65 further back into the formation. It should be noted that for thepurpose of simplicity, the damage shown in these figures is shown asvery shallow damage and as homogeneous in each of the damage regions. Inpractices the damage mechanism will be non-homogeneous and much morecomplex than shown.

[0089] After the packers have been inflated, the pressure in the tubingis increased to the selected initial stimulation pressure. Thisstimulation pressure will be based upon factors such as whether theformation is of sandstone or carbonate material, the formation pressure,the type of formation damage expected, the fluid in the formation and byexperience in stimulating wells in each particular oil field. Thisinitial stimulation pressure will generally be higher than thestabilized formation pressure by at least 500 psi.

[0090] The fluid control valve is then moved to the injection position.Nitrogen is injected into the well bore region between the packers andbegins to permeate the surface of the well bore into the formation asshown in FIG. 8c. Nitrogen gas molecules are significantly smaller thanthe molecules of liquid treating fluids such as hydrochloric acid, andwill therefore penetrate pore spaces which are almost completely blockedby particles from drilling fluids or crushed drilling fines. Since thepermeability to gas is much higher than the permeability to liquid forany formation, the gas will preferentially permeate into the formationleaving any well bore liquids in the well bore. The size of the gasmolecules will allow it to migrate between the compacted particles fromthe drilling fluid and the drilling fines from the formation itself andcreate gas filled channels 58 and tiny pockets of gas 59.

[0091] After injecting nitrogen for a brief period of 15 seconds toseveral minutes, the fluid control valve is moved to the surge position.The flow of nitrogen from the tubing into the formation is shut offimmediately and the pressure in the well bore between the packers isreleased back to the well bore above the top packer. Since the pressurein the annular region between the packers and in the formation is muchhigher than the pressure in the well bore above the top packer, a surgeof fluids from between the packers takes place.

[0092] As the pressure between the packers is released, the pressurizednitrogen gas in that region will expand and force most of the liquidthat remains there through the tool to the well bore above the toppacker. FIG. 8d shows how this sudden decompression in the well boreregion will cause a high pressure drop across the particles at the faceof the well bore and the nitrogen in the tiny pockets 59 behind theseparticles will expand and force some of these particles into the wellbore. The same thing happens along gas filled channels 58. The velocityof the gas flow along these channels will be relatively high and some ofthe particulate matter will be removed from the surface of thesechannels and forced out to the well bore as the channel widens. Thepressure deeper in the gas filled channel will also result in newchannels 60 opening up through pore spaces previously blocked with smallparticles.

[0093] The fluid control valve is again placed in the injection positionand nitrogen is injected into the formation a second time as shown byFIG. 9a. The duration of injection can remain constant or a longerinjection period can be utilized to inject nitrogen further into thereservoir. The nitrogen will move further into the formation and extendpreviously opened gas filled channels even deeper as shown at 61. Whenthe fluid control valve is moved to the surge position as in FIG. 9b,more damaging particles are removed and more channels 62 are cleared bynitrogen expanding and flowing back to the well bore.

[0094] Subsequent injections cycles result in deeper penetration ofnitrogen into the liquid invaded zone and all the way through to the oilzone as shown by channels 63 in FIG. 9c. Since nitrogen is soluble inliquids, some of the nitrogen will also be absorbed into liquidblockages such as emulsions or colloidal suspensions. When the pressureis released quickly during the following surge phase, the pressurizednitrogen will expand and force some of the blocking solids and liquidsfrom the pore spaces into the gas filled channels and out to the wellbore. Additional new channels 64 will be opened up for flow.

[0095] The desorption of liquids into the nitrogen gas may also allowfor regained permeability in formations where clays and other mineralshave absorbed liquids during the drilling or completion process and thisabsorption of liquids has resulted in swelling of these particles and areduction in the permeability of the formation.

[0096] This injection and surge procedure can be repeated an unlimitednumber of times. The effectiveness of each cycle will be dependant uponthe characteristics of each formation and the types of damagesurrounding that particular well bore. The optimal pressure differentialbetween injection pressure and release pressure may be different fordiffering types of formations. The stimulation pressure may be variedduring each subsequent injection/surge sequence or held constant.

[0097] It should be realized that it is advantageous to control thepressure draw down in the formation during the surge cycle in order toprevent the reservoir fluid from flowing into the well bore region eachtime the pressure is released. By preventing liquid from refilling thepore spaces occupied by the nitrogen, the amount of nitrogen used willbe minimized, surge time will be minimized and the effectiveness of theprocedure will be improved since the well bore pressure will declinefaster if no liquid must be forced through the tool with the nitrogen.

[0098] The pressure drawdown in the formation can be controlled bymeasuring the pressure in the well bore adjacent to the formation andusing that pressure in the microprocessor within the tool to close thefluid control valve as soon as the well bore pressure declines to aspecified set pressure, typically the static formation pressure.

[0099] After the final injection surge cycle, all of the nitrogen can bereleased back to the well bore above the packer, and oil will flow backthrough the formation to the well bore through the pore spaces whichhave been cleaned by the nitrogen surges. The fluid control valve canthen be moved to the closed position.

[0100] The fluid control valve can then moved to the deflation positionand the packers will be deflated. The tubing string can be coiled backonto the reel until the packers are at an unstimulated section of thewell bore. This entire procedure can be repeated at as many intervals inthe well bore as desired to effectively stimulate the well. It should benoted that prior to deflating the packers, with the fluid control valvein the closed position, the buildup up of reservoir pressure can bemonitored and evaluated to determine the relative permeability of theformation and whether any formation damage remains in the well boreregion.

[0101] Evaluation

[0102] Evaluation of porous formations before, during and after astimulation treatment can be an important part of determining theeffectiveness of any stimulation treatment. The permeability of theformation and the level of damage in the formation, determined prior toa stimulation treatment provides a base line against which laterevaluations can be compared. A post treatment evaluation will thenascertain whether the treatment was successful, had no effect, or wasdetrimental.

[0103] Pressure transient analysis is a well developed science whichutilizes the pressure measured during a formation response sequence.This sequence is created by withdrawing or injecting fluid into a porousformation for some period of time and then stopping the fluid flow andmonitoring the pressure response to that fluid flow. This change instate from flowing to non-flowing creates a pressure transient in thewell bore and in the formation that is a reflection of thecharacteristics of the formation.

[0104] A drill stem test is a commonly practised method of evaluatingformations to determine the permeability and damage. After inflating thepackers and evacuating the tubing string, a pre-stimulation drill stemtest can be conducted by opening the fluid control valve to allowformation fluids to flow into the tubing string for a period of time andthen closing the fluid control valve to monitor the pressure build up inthe formation. Pressure transient analysis will allow the permeabilityand formation damage to be calculated. Prior to commencing injection ofgas for the stimulation treatment, the fluid can then be purged from thetubing string into the well bore by pressurizing the tubing string withgas and opening the fluid control valve. A second drill stem test can beconducted at the conclusion of the stimulation treatment to evaluate thelevel of formation damage and stimulation effectiveness.

[0105] A second method for the evaluation of stimulation effectivenessinvolves monitoring of pressures as fluid (usually acid) is injected ata constant rate. As damage is removed from the formation by acid, theinjection pressure declines. This technique is relatively new andrequires pressure monitoring equipment, such as provided by the presentinvention, to be in place in order to be utilized effectively.

[0106] The present invention introduces the use of real time evaluationof stimulation effectiveness through continuous monitoring of pressurewithin the tubing string, within the well bore in the region isolatedfor treatment, within the well bore above the packer(s), and thepressure withing the packers. These pressure monitoring and analysiscapabilities allow new evaluation methods to be developed and utilized.For example, a closed chamber injection method can be employed wherebythe tubing string is pressurized with gas to the same pressure prior tothe start of each injection cycle and no additional gas is added to thetubing string during that injection cycle. This initial pressure must besignificantly higher (greater than 20%) than the static formationpressure. If the injection time for each cycle is exactly the same, thenmonitoring and evaluating the tubing pressure and well bore pressureduring each cycle may be an indicator of the stimulation effectiveness.

[0107] Major Advantages of the Preferred Embodiment for Repeated SurgeStimulation Technique

[0108] The use of a single string coiled tubing string for deployment ofthe down hole apparatus into a well bore which is not overbalanced inpressure is advantageous compared to the use of other tubulararrangements for several reasons.

[0109] The development of an electrically operable multi-position fluidcontrol valve for use in the preferred embodiment provides the followingadvantages:

[0110] 1. It simplifies the down hole tool design which minimizes thelength of tool. This is especially critical for pressure deployment ofthe tools into live wells. It is also important in treating horizontalwells with a short horizontal bend radius, since it reduces the lengthof the relatively inflexible portion of the tool.

[0111] 2. It simplifies the electronics design from both hardware designand software design viewpoints. This in turn improves the reliability ofthe control system.

[0112] 3. It allows all valve operations to be performed independent ofthe pressure in any tubing string or in the well bore.

[0113] 4. It allows all valve operations to be performed independent oftensile or compressive forces in any of the tubing strings.

[0114] 5. It allows fluid to be pumped into the well bore below the toppacker independent of whether the packers are inflated or not.

[0115] 6. It provides a means of circulating fluids down the tubing andup the well bore when a build up of solids or any particulate matter ispreventing the tubing or tool from being withdrawn from the well bore.

[0116] A major advantage of the, repeated surge stimulation technique isthat the amount of nitrogen utilized can be very closely controlled andcan be minimized since the nitrogen in the injection string never needsto be vented back to surface, except at the end of operations.

[0117] Nitrogen gas molecules are significantly smaller than themolecules of liquid treating fluids such as hydrochloric acid, and willtherefore penetrate pore spaces which are almost completely blocked byparticles from drilling fluids or crushed drilling fines.

[0118] Other Embodiments of the Present Invention

[0119] The preceding disclosure of the preferred embodiment is only oneof a number of embodiments which are envisioned for this invention.

[0120] The use of a normal jointed tubular string in conjunction withwireline spooled from a conventional wireline logging unit would providethe same capabilities as the preferred embodiment. However, jointedtubing is more complex operationally because it takes longer to runjointed tubing into a well, and wireline must be inserted and withdrawnin order to remove joints of tubing each time the packer(s) are moved toa different setting depth.

[0121] The use of concentric coiled tubing allows the tools to bedeployed in a well either filled with liquid or with a very high fluidlevel. Concentric tubing may uses the annular area between the two coilsto inject fluids into the well bore and the inner coil to return fluidsfrom the formation. This embodiment has the added advantage thatproduced fluids could be circulated from the tubing by allowing nitrogengas from the outer tubing to flow into the inner tubing. However, thisembodiment is more complex to assemble and operate and has significantlimitations in well depth as a result of the extreme weight of theassembled concentric coiled tubing reel and normal weight restrictionsimposed on highways.

[0122] Both singular packer and multiple packer embodiments areanticipated with the present invention. Single packer assemblies allowthe well bore to be divided into two regions, one above the packer andone below the packer, with evaluation and stimulation of only the regionbelow the packer. There are very few situations where a single packerassembly would be advantageous over a dual packer assembly and manyadvantages to the dual packer arrangement. It is also envisioned thatmultiple packer arrangements be utilized in order to allow two or morediscreet intervals to be evaluated and or stimulated simultaneously.

[0123] A preferred embodiment discloses the use of a singlemulti-position fluid control valve as an optimal valve arrangement tosimplify the design of the tool and provide maximum reliability.However, the method of the present invention can also be effective ifmultiple electrically operated valves or any other type or combinationof valves is used to provide fluid control functions.

[0124] A preferred embodiment previously disclosed utilizes pressurecreated by fluids injected into the formation from the tubing string toprovide the energy to remove formation damaging materials from the porespaces in the formation. The use of the natural energy within theformation can also be utilized to create a surge of fluid flow into thewell bore and the tubing string. The apparatus disclosed in the presentinvention allows a method of surging whereby the packers are firstinflated with gases from the tubing string, after which the tubingpressure is vented back to surface. The tubing string must be utilizedto receive the surge of fluids, since the well bore pressure above thepacker(s) will be either equal to or greater than the formation pressureand will not allow fluids and pressure to flow from the formation.

[0125] The fluid control valve is then opened to allow the naturalenergy from the formation to flow into the tubing string briefly, thenclosed until the formation pressure in the well bore and near well borearea is replenished from the formation. This would typically meanallowing the pressure in the well bore to reach at least 70% of theactual formation pressure. The fluid control valve can be opened againfor another surge, and then shut in. This procedure can be repeated asrequired until sufficient formation damaging material has been removed.This embodiment works particularly well for gas wells or wells withrelatively low liquid inflow since the gas pressure in the tubing stringcan be vented at surface to maintain a relatively low pressure in thetubing string down hole and a high pressure surge differential when thevalve is opened. If significant liquid inflow results in low surgecapability, the liquid can be purged from the tubing string by deflatingthe packers, opening the fluid control and pumping gas into the tubingstring with sufficient pressure to displace the liquid into the wellbore. Additional surging of the same or another interval can then becarried out.

I claim:
 1. A method of treating an underground formation that has beenpenetrated by a well, the well having a wellbore, the method comprisingthe steps of: lowering a valve into the well until the valve is adjacentthe formation with the valve being placed to control flow of fluidbetween the formation and the wellbore; establishing a pressuredifferential across the valve; and selectively and repeatedly openingand closing the valve to cause cyclical pressure variation in theformation and induce surges of fluid from the formation into thewellbore.
 2. The method of claim 1 further comprising the steps of:providing a source of pressurized treatment fluid in fluid communicationwith the valve; and injecting treatment fluid from the source ofpressurized treatment fluid into the formation to increase the pressurein the formation above the formation pressure prior to each surge offluid from the formation.
 3. The method of claim 1 in which the cyclicalpressure variation rises above formation pressure during injection oftreatment fluid and drops below formation pressure during surge of fluidfrom the formation.
 4. The method of claim 3 in which treatment fluid isinjected into the formation through a first flow channel extending fromthe surface and fluid from the formation is returned towards the surfacethrough a second flow channel distinct from the first flow channel. 5.The method of claim 4 in which the valve has multiple ports, includingat least a first port for controlling flow in the first flow channel anda second port for controlling flow in the second flow channel.
 6. Themethod of claim 4 in which the first flow channel is formed by theinterior of a first string of tubing and the second flow channel isformed by an annulus between the first string of tubing and a secondstring of tubing.
 7. The method of claim 1 further comprising the stepof isolating the formation prior to inducing pressure surges in theformation.
 8. The method of claim 7 in which the formation is isolatedby inflating a packer above the formation to be treated.
 9. The methodof claim 8 in which inflating the packer comprises injecting fluid fromthe first flow channel into the packer under control of the valve. 10.The method of claim 8 further comprising the step of inflating a packerbelow the formation to be treated.
 11. The method of claim 1 furthercomprising the step of monitoring pressure variation in the formationduring treatment of the formation.
 12. The method of claim 11 furthercomprising the step of terminating release of pressure from theformation when the formation pressure reaches a pre-set pressure. 13.The method of claim 12 in which the pre-set pressure is the formationpressure.
 14. The method of claim 1 further comprising the step ofmonitoring pressure variation in the wellbore during treatment of theformation.
 15. The method of claim 1 further comprising the step ofmonitoring pressure variation in the first flow channel during treatmentof the formation.
 16. The method of claim 1 in which the treatment fluidinjected into the formation is nitrogen.
 17. The method of claim 1 inwhich, between surges, the formation pressure is allowed to build upnaturally, without injection of fluid from the surface.
 18. A method ofcontrolling fluid flow in a well, the method comprising the steps of:lowering into the well a multiport valve operable by an electric motor;and controlling fluid flow in the well by opening and closing ports inthe multiport valve under instruction from the surface to the electricmotor.
 19. The method of claim 18 in which the multiport valve issuspended on the end of a tubing string and further comprising the stepof injecting fluid through a first flow channel to the multiport valveto force fluid in the wellbore towards the surface.
 20. The method ofclaim 19 in which the multiport valve is provided with at least onepacker suspended on the tubing string below the multiport valve andcontrol of fluid is carried out while the packer is not inflated.
 21. Amethod for treating wells, the method comprising the steps of: providinga tubular arrangement for installation in a well bore which produces twodistinct channels for segregated fluid flow; the first channel providinga flow path from pumping equipment at surface to a down hole toolassembly; and the second channel for fluid flow from the down hole toolassembly to flow control equipment at surface; lowering a bottom holeassembly which has been attached to the distal end of the tubulararrangement into the well bore to the desired depth; isolating at leastone linear segment of the well bore from the remainder of the well boreby the use of one or more well bore sealing elements or packers whichform part of the down hole tool assembly; filling the first flow channelwith fluid and opening a valve in the down hole assembly to allow thefluid in the first channel to flow into the formation adjacent to thesection of the well bore which has been isolated from the remainder ofthe well bore; closing said valve in the down hole assembly; and openinga valve in the down hole assembly to allow the fluids injected into theformation, as well as fluids and solid materials from the formation toflow back into the second flow channel.
 22. A method for removing solidmaterials including formation cuttings, formation fines, sand, drillingfluid suspended solids, drilling fluid filter cake, sediments, andprecipitates from a well bore and from the pore spaces in the formationsurrounding said well bore, such method comprising; providing a tubulararrangement for installation in a well bore which produces two distinctchannels for segregated fluid flow; the first channel for fluid flowfrom flow control equipment at surface to a down hole tool assembly; andthe second channel for fluid flow from the down hole tool assembly toflow control equipment at surface; lowering a bottom hole assembly whichhas been attached to the distal end of the tubular arrangement into thewell bore to the desired depth; isolating at least one linear segment ofthe well bore from the remainder of the well bore by the use of one ormore well bore sealing elements or packers which form part of the downhole tool assembly; filling the first flow channel with fluid andopening a valve in the down hole assembly to allow the fluid in thefirst channel to flow into the formation adjacent to the section of thewell bore which has been isolated from the remainder of the well bore;closing said valve in the down hole assembly; and opening a valve in thedown hole assembly to allow the fluids injected into the formation, aswell as fluids and solid materials from the formation to flow back intothe second flow channel.
 23. A method for removing liquids, emulsions,colloidal suspensions and other multi-phase fluids from the regionsurrounding a well bore, such method comprising; providing a tubulararrangement for installation in a well bore which produces two distinctchannels for segregated fluid flow; the first channel for fluid flowfrom flow control equipment at surface to a down hole tool assembly; andthe second channel for fluid flow from the down hole tool assembly toflow control equipment at surface; lowering a bottom hole assembly whichhas been attached to the distal end of the tubular arrangement into thewell bore to the desired depth; isolating at least one linear segment ofthe well bore from the remainder of the well bore by the use of one ormore well bore sealing elements or packers which form part of the downhole too assembly; filling the first flow channel with fluid and openinga valve in the down hole assembly to allow the fluid in the firstchannel to flow into the formation adjacent to the section of the wellbore which has been isolated from the remainder of the well bore;closing said valve in the down hole assembly; and opening a valve in thedown hole assembly to allow the fluids injected into the formation, aswell as fluids and solid materials from the formation to flow back intothe second flow channel.
 24. The method of claim 21 where two sealingelements or packers are used to isolate a segment of the well bore fromthe remainder of the well bore on either side of said segment.
 25. Themethod of claim 21 where more than one segment is isolated from eachother and the remaining well bore through the use of three or moresealing elements or packers.
 26. The method of claim 21 where theprocess of opening a down hole valve, injecting fluid into the formationand then closing said valve, followed by the process of opening a valveand allowing the injected fluids to surge back into the second flowchannel is repeated one or more times.
 27. The method of claim 21 wherethe first fluid channel is formed within a continuous string of coiledtubing, and the second fluid channel is formed in the annular areabetween the coiled tubing and the well casing which may extend to thebottom hole assembly. Where the casing only extends a portion of the wayto the bottom hole assembly, the open hole well bore will form thecontinuation of the casing for purposes of forming the outer wall of thefluid channel. The down hole assembly is attached to the end of thecoiled tubing.
 28. The method of claim 21 where the first channel isformed within a string of jointed tubing or drill pipe and the secondfluid channel is formed in the annular area between the jointed tubingor drill pipe and the well casing which may extend to the bottom holeassembly. Where the casing only extends a portion of the way to thebottom hole assembly, the open hole well bore will form the continuationof the casing for purposes of forming the outer wall of the fluidchannel. The down hole assembly is attached to the end of the jointedtubing or drill pipe.
 29. The method of claim 21 where a string ofcoiled tubing is located axially inside a second string of coiled tubingand this concentric coil-in-coil tubing string is used to deliver thedown hole assembly, and the fluid channels in each of the coils issegregated from the other such that one coil forms the first fluidchannel and the other coil forms the second channel.
 30. The method ofclaim 29 where the first fluid channel is formed by either of the inneror outer coiled tubing string, and the second fluid channel is formed bythe annular area between the outer coiled tubing string and the casingand/or well bore diameter.
 31. The method of claim 21 where the downhole assembly is delivered by jointed tubulars and a single string ofcoiled tubing is then inserted axially inside the jointed tubulars andsealed from the jointed tubing such that the fluid channels in each ofthe jointed and coiled tubing strings is segregated from the other andone fluid channel forms the first fluid channel and the other forms thesecond fluid channel.
 32. The method of claim 31 where the first fluidchannel is formed by either of the inner coiled tubing string or theouter jointed tubing string, and the second fluid channel is formed bythe annular area between the outer coiled tubing string and the casingand/or well bore diameter.
 33. The method of claim 21 where two stringsof concentric coiled tubing are located axially beside each other andthis dual coiled tubing string is used to deliver the down holeassembly, and the fluid channels in each of the coils is segregated fromthe other such that one coil forms the first fluid channel and the othercoil forms the second channel.
 34. The method of claim 33 where thefirst fluid channel is formed by either coiled tubing string, and thesecond fluid channel is formed by the annular area between the coiledtubing strings and the casing and/or well bore diameter.
 35. The methodof claims 21, and 32, 33 where the sealing elements or packers areinflatable in nature and are expandable by the use of a valve in thedown hole assembly to allow pressure from the first fluid channel toflow into the sealing elements.
 36. The method of claim 35 where a valvein the down hole assembly allows the pressure and fluid from the packersto be vented to the second fluid channel to deflate the packers back totheir original shape.
 37. The method of claim 21 where the pressure atthe down hole assembly in the first fluid channel, prior to opening saidvalve to allow fluid to flow into the isolated well bore segment, ishigher than the pressure in the formation.
 38. The method of claim 21where the second fluid channel is initially void of fluids.
 39. Themethod of claim 21 where the pressure at the down hole assembly in thesecond fluid channel is less than the formation pressure.
 40. The methodof claim 21 where the fluid injected into the reservoir is in a liquidstate.
 41. The method of claim 21 where the fluid injected into thereservoir is in a gaseous state.
 42. The method of claim 21 where thefluid injected into the reservoir is a two phase mixture of fluids in agaseous and liquid state.
 43. The method of claim 21 where the injectedfluid is alternated between a liquid phase for one injection cycle and agas for the subsequent injection cycle.
 44. An apparatus for use in welltreating and evaluation operations which comprises: a tubulararrangement for installation in a well bore which produces two distinctchannels for segregated fluid flow; the first channel providing a flowpath from pumping equipment at surface to a down hole tool assembly; andthe second channel for fluid flow from the down hole tool assembly toflow control equipment at surface; a bottom hole assembly which has beenattached to the distal end of the tubular arrangement; at least one wellbore sealing element or packer which forms part of the down hole toolassembly and is used to isolate a linear segment of the well bore fromthe remainder of the well bore; and a fluid control valve system in thedown hole assembly which allows the fluid movement through the tool andthe surrounding well bore regions to be controlled from surface.
 45. Theapparatus of claim 44 where the fluid control valve comprises: a valvehousing with a longitudinal bore in the housing; multiple fluid passagesdrilled longitudinally in the valve housing parallel to the valve bore,said passages providing fluid flow from the tubing string above thevalve, the well bore area above the packers adjacent to the valve, thewell bore area below the upper packer, and the interior area of thepacker(s); passages drilled at positions along the valve bore andperpendicular to the valve bore which connect the valve bore with thefluid passages with openings into the valve bore and the passages; avalve spool which is inserted into the valve bore and which hascylindrical seals around it to seal the area between itself and thevalve bore, as well as an area of reduced diameter and of sufficientlength to allow fluid to flow between any two of the openings; and avalve operator which imparts linear motion to the valve spool in orderto position in any one of a given number of positions along the valvebore.
 46. The apparatus of claim 45 where the valve operator comprisesan electrically operable means of imparting linear motion to the valvespool.
 47. The apparatus of claim 46 where the electrically operablemeans comprises: an electrical motor with rotary output; a speedreduction module to reduce the speed of the output shaft of the motor;and a motion conversion module which converts the rotary motion from thespeed reduction module to linear motion.
 48. The apparatus of claim 47which includes a mechanism for sensing or determining the location ofthe linear shaft and the valve spool.
 49. The apparatus of claim 47where the motor is controlled by a microprocessor or microcontrolledwhich uses the sensing mechanism of claim 28 and control signals fromthe tool operator to stop and start the motor.
 50. The apparatus ofclaim 47 where the microprocessor or micro controller is connected to acomputer at the surface of the well and each of the computer at surfaceand the microprocessor or micro controller have software code sufficientto allow them to communicate to each other and to allow commands to beimplemented into the surface computer for moving the valve spool to adesired location in the valve bore.
 51. The apparatus of claim 47 wherepressure sensors in the down hole apparatus are connected to themicroprocessor or micro controller and where the micro controller ormicroprocessor has software code which enables it to determine thepressure measured by the pressure sensors and to implement movements ofthe valve spool, independent from the tool operator at surface, basedupon given pressure parameters.
 52. A method of operating a multipleposition down hole valve which operates independent of any mechanicalmovement of the tubing string and independent of any pressure in thetubing string or well bore, such method comprising: using computersoftware to initiate a command in a computer or microprocessor or microcontroller which is located at the surface of the well location; havingthe surface computer send that command to a second microprocessor ormicro controller located in the down hole assembly near the fluidcontrol valve; using the down hole microprocessor or micro controller tosense or determine the position of the valve; using an electricallyoperated motor to provide the mechanical force necessary to move thevalve from one position to another position; using the down holemicroprocessor or micro controller to switch electrical power in theappropriate polarity to the electrically operated valve control motor;using the down hole microprocessor or micro controller to sense when thevalve has reached the required position; and using the down holemicroprocessor or micro controller to switch off the electrical power tothe electrically operated valve motor.
 53. The method of claim 52 wherea third computer located remotely from the well location is connected bya wireless communications network to the computer at the well locationand the command to operate the fluid control valve is given from theremotely operated computer.
 54. A method of operating a multipleposition down hole valve which operates independent of any mechanicalmovement of the tubing string and independent of any pressure in thetubing string or well bore, such method comprising: using computersoftware to initiate a command in a computer or microprocessor or microcontroller which is located at the surface of the well location; havingthe surface computer send that command to a second microprocessor ormicro controller located in the down hole assembly near the fluidcontrol valve; using the down hole microprocessor or micro controller tosense or determine the position of the valve; using an electricallyoperated motor to provide the mechanical force necessary to move thevalve from one position to another position; using electrically operatedpressure sensing devices which are connected to the down holemicroprocessor or micro controller, said pressure sensing devicesmeasuring the pressure in one or more of the locations within the tooland well bore which might at any time during the well evaluation ortreating operations be different from the pressure at any other locationwithin the tool or well bore, such as the pressure in the tubing string,the pressure in any secondary tubing string, the pressure in anyinflatable packers, the pressure in the well bore above the top packerand the pressure in the well bore below the top packer; using the downhole microprocessor or micro controller to use the pressure sensing datato automatically switch electrical power in the appropriate polarity toelectrically operated valve control motor and to move the valve to aspecified position based upon preset criteria for the pressure data;using the down hole microprocessor or micro controller to sense when thevalve has reached the required position; and using the down holemicroprocessor or micro controller to switch off the electrical power tothe electrically operated valve motor.
 55. A method for evaluating wellswhich comprises: providing a tubular arrangement for installation in awell bore which is of a continuous nature and is spoilable on to a reel;lowering a bottom hole assembly that has been attached to the distal endof the coiled tubing into the well bore to the desired depth, saidassembly containing inflatable well bore sealing means, electricallyoperable multi-position fluid control valve, electrically operablemicro-controller, electrically operable pressure sensing devices, andelectrically operable communication modem; pressurizing the coiledtubing to a pressure at the down hole assembly which is greater than thepressure in the well bore at the down hole assembly, said pressuresbeing monitored by the sensing devices in the down hole assembly;opening the fluid control valve in the down hole assembly to allow thefluid in the coiled tubing to flow into the inflatable packers therebyisolating at least one linear segment of the well bore from theremainder of the well bore; closing said valve in the down holeassembly; reducing the pressure in the coiled tubing to a pressure atthe down hole assembly which is less than the pressure in the well boreat the down hole assembly, said pressures being monitored by the sensingdevices in the down hole assembly; opening the fluid control valve inthe down hole assembly to allow the fluids in the section of the wellbore which has been isolated, as well as fluids and solid materials fromthe formation adjacent to it, to flow into through the valve and intothe coiled tubing; closing said valve in the down hole assembly andrecording the pressure response in the well bore isolated from theremainder of the well bore using the pressure sensing devices in thedown hole assembly; and opening the fluid control valve in the down holeassembly to allow the fluids in the inflatable packers to flow into thewell bore until the pressure has been equalized and the packers havedeflated.
 56. The method of claim 55 where more than one period ofinflow into the tubing string or more than one period of monitoringpressure build up in the well bore is completed.
 57. The method of claim55 where the fluid used to pressurize the coiled tubing string is a gas.58. The method of claim 55 where the fluid used to pressurize the coiledtubing string is a mixture of liquid and gas such that the amount ofliquid does not create a hydrostatic pressure in the tubing greater thanthe pressure in the formation adjacent to the down hole assembly.